To produce oil or gas, a well is drilled into a subterranean formation that is an oil or gas reservoir.
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.
Drilling is the process of drilling the wellbore. After a portion of the wellbore is drilled, sections of steel pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.
Completion is the process of making a well ready for production or injection. This principally involves preparing a zone of the wellbore to the required specifications, running in the production tubing and associated downhole equipment, as well as perforating and stimulating as required.
Intervention is any operation carried out on a well during or at the end of its productive life that alters the state of the well or well geometry, provides well diagnostics, or manages the production of the well.
For example, completion or intervention treatments can include, for example, sand control, including gravel packing with mechanical screens.
Drilling and Drilling Fluids
A well is created by drilling a hole into the earth (or seabed) with a drilling rig that rotates a drill string with a drilling bit attached to the downward end. Usually the borehole is anywhere between about 5 inches (13 cm) to about 36 inches (91 cm) in diameter. As upper portions are cased or lined, progressively smaller drilling strings and bits must be used to pass through the uphole casings or liners, which steps the borehole down to progressively smaller diameters.
While drilling an oil or gas well, a drilling fluid is circulated downhole through a drillpipe to a drill bit at the downhole end, out through the drill bit into the wellbore, and then back uphole to the surface through the annular path between the tubular drillpipe and the borehole. The purpose of the drilling fluid is to maintain hydrostatic pressure in the wellbore, lubricate the drill string, and carry rock cuttings out from the wellbore.
The drilling fluid can be water-based or oil-based. Oil-based fluids tend to have better lubricating properties than water-based fluids, nevertheless, other factors can mitigate in favor of using a water-based drilling fluid. Such factors may include but not limited to presence of water-swellable formations, need for a thin but a strong and impermeable filtercake, temperature stability, corrosion resistance, stuck pipe prevention, contamination resistance and production protection.
Completion and Completion Fluids
During completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil and gas from a well. Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, and controlling excessive water production.
Fluid-Loss Control and Filtercake Formation
Fluid loss refers to the undesirable leakage of a fluid phase of any type of drilling, completion, or other treatment fluid into the permeable matrix of a subterranean formation. Fluids used in drilling, completion, or servicing of a wellbore can be lost to a subterranean formation while circulating the fluids in the wellbore. In particular, the fluids may enter the subterranean formation via depleted zones, zones of relatively low pressure, lost circulation zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth. The extent of fluid losses to the formation may range from minor (for example less than 10 bbl/hr), which is referred to as seepage loss, to severe (for example, greater than 500 bbl/hr), which is referred to as complete loss. The greater the fluid loss, the more difficult it is to achieve the purpose of the fluid.
Fluid-loss control refers to treatments designed to reduce fluid loss. Providing effective fluid-loss control for fluids during certain stages of well operations is usually highly desirable.
The usual approach to fluid-loss control is to substantially reduce the permeability of the matrix of the zone with a fluid-loss control material that blocks the permeability at or near the face of the rock matrix of the zone. For example, the fluid-loss control material may be a particulate that has a size selected to bridge and plug the pore throats of the matrix. As the fluid phase carrying the fluid-loss control material leaks into the formation, the fluid-loss control material bridges the pore throats of the matrix of the formation and builds up on the surface of the borehole or fracture face or penetrates only a little into the matrix. All else being equal, the higher the concentration of the appropriately sized particulate, the faster bridging will occur. The buildup of solid particulate or other fluid-loss control material on the walls of a wellbore or a fracture is referred to as a filtercake. Such a filtercake can help block the further loss of a fluid phase (referred to as a filtrate) into the subterranean formation. A fluid-loss control material is specifically designed to lower the volume of a filtrate that passes through a filter medium. Accordingly, a fluid-loss control material is sometimes referred to as a filtration control agent.
Fluid-loss control fluids typically include an aqueous continuous phase and a high concentration of a viscosifying agent (usually crosslinked), and usually, bridging particles, such as graded sand, graded salt particulate, or graded calcium carbonate particulate. Through a combination of viscosity, solids bridging, and cake buildup on the porous rock of the borehole, such fluids are often able to substantially reduce the permeability of a zone of the subterranean formation to fluid loss.
For example, commonly used fluid-loss control pills contain high concentrations (100 to 150 lbs/1000 gal) of derivatized hydroxyethylcellulose (“HEC”). HEC is generally accepted as a viscosifying agent affording minimal permeability damage during completion operations. Normally, HEC polymer solutions do not form rigid gels, but control fluid loss by a viscosity-regulated or filtration mechanism. Some other viscosifying polymers that have been used include xanthan, guar, guar derivatives, carboxymethylhydroxyethylcellulose (“CMHEC”), and starch. Viscoelastic surfactants can also be used.
Crosslinked polymers can also be used for fluid-loss control. Crosslinking the gelling agent polymer helps suspend solids in a fluid as well as provide fluid-loss control. Further, crosslinked fluid-loss control pills have demonstrated that they require relatively limited invasion of the formation face to be fully effective. To crosslink the viscosifying polymers, a suitable crosslinking agent that includes polyvalent metal ions is used. Boron, aluminum, titanium, and zirconium are common examples.
A fluid-loss control pill is a treatment fluid that is designed or used to provide some degree of fluid-loss control. A fluid-loss control pill is usually used prior to introducing another drilling fluid or treatment fluid into zone. In addition, fluid-loss control materials are sometimes used in drilling fluids, various types of completion fluids, or various types of treatment fluids used in intervention.
Filtercake Degradation
After a filtercake is formed, which can occur during drilling or various completion operations, it is usually desirable to restore the permeability of a producing zone for production from the zone. If the formation permeability of the desired producing zone is not restored, production levels from the formation can be significantly lower. Any filtercake or any solid or polymer filtration into the matrix of the zone resulting from a fluid-loss control treatment must be degraded to restore the formation's permeability, preferably to at least its original level. This is often referred to as clean up. In many cases, the filtercake adheres strongly to the borehole penetrating the formation, which makes clean up a difficult process.
Chemicals used to help degrade or remove a filtercake are called breakers.
Breakers for helping to degrade or remove a filtercake must be selected to meet the needs of each situation. First, it is important to understand the general performance criteria for degrading or breaking of a filtercake. Premature degradation of a filtercake can cause undesired fluid loss into a formation. Inadequate degradation of a filtercake can result in permanent damage to formation permeability. A breaker for degrading or removing a filtercake should be selected based on its performance in the temperature, pH, time, and desired filtercake profile for each specific fluid-loss application.
The term “degrade,” as used herein, refers to at least a partial degradation of a material in the filtercake. No particular mechanism is necessarily implied by degrading or breaking regarding a filtercake. A filtercake can be degraded or removed, for example, by dissolving the bridging particulate, chemically degrading or hydrolyzing a viscosity-increasing agent in the filtercake, reversing or degrading crosslinking if the viscosity-increasing agent is crosslinked, or any combination of these. More particularly, for example, a fluid-loss control agent can be selected for being insoluble in water but soluble in acid, whereby changing the pH or washing with an acidic fluid can dissolve a fluid-loss control agent or hydrolyze a viscosity-increasing agent in the filtercake.
Chemical breakers used to help clean up a filtercake or break the viscosity of a viscosified fluid are generally grouped into several classes: oxidizers, enzymes, chelating agents, and acids.
A filtercake usually includes sized calcium carbonate or other acid-soluble particulate and an acid-degradable polymeric material.
Oil-Swellable Elastomer
Oil-swellable elastomers have various applications in wells, especially wells used for producing hydrocarbons. For example, an oil-swellable elastomer can be used in downhole tools having swellable components, such as swellable packers. For another example, oil-swellable elastomers can be used as particulate in various hydraulic fracturing operations as part of a proppant matrix. In yet another example, an oil-swellable particulate can be used as a particulate in a gravel pack.
An oil-swellable elastomer swells when exposed to a fluid comprising a hydrocarbon. The elastomer swells as a hydrocarbon enters and is trapped in the elastomer matrix due to the natural affinity of the polymer molecules of the elastomer and the hydrocarbon. Oil is absorbed into the oil-swellable elastomer through diffusion. Through the random thermal motion of the atoms that are in the liquid hydrocarbons, oil diffuses into the elastomer. As hydrocarbon molecules are absorbed into the polymer matrix of the elastomer, it causes the elastomer to stretch and expand. Swelling of the elastomer in the presence of oil is irreversible (whereas water-swelling elastomer, which operates on osmosis phenomenon, is reversible process). The swelling continues until the internal stresses inside the elastomer reach equilibrium. That is, the swell pressure increases until diffusion can no longer occur.
Although the hydrocarbon of the fluids used for this purpose should not degrade the elastomer, they will alter its mechanical properties, such as hardness and tensile strength, depending on the volume increase.
An example of an application of oil-swellable elastomers is in oil-swellable downhole tools such as swell screens used for sand control.
Sand control is an operation to reduce production of formation sand or other fines from a poorly consolidated subterranean formation. In this context, “fines” are tiny particles, typically having a diameter of 43 microns or smaller, that have a tendency to flow through the formation with the production of hydrocarbon fluids. The fines have a tendency to plug small pore spaces in the formation and block the flow of oil. As all the hydrocarbon is flowing from a relatively large region around the wellbore toward a relatively small area around the wellbore, the fines have a tendency to become densely packed and screen out or plug the area immediately around the wellbore. Moreover, the sand and fines are highly abrasive and can be damaging to pumping and other oilfield equipment and operations.
Placing a relatively larger particulate near the wellbore can help filter out the sand or fine particles and prevents them from flowing into the well with the produced fluids. The primary objective is to stabilize the formation while causing minimal impairment to well productivity. The particulate used for this purpose is referred to as “gravel.” In the oil and gas field, and as used herein, the term “gravel” is refers to relatively large particles ranging in diameter from about 0.1 mm up to about 2 mm. Generally, a particulate having the properties, including chemical stability, of a low-strength proppant is used in gravel packing. An example of a commonly used gravel packing material is sand having an appropriately large particulate size range.
In general, a mechanical screen is placed in the wellbore and the surrounding annulus is packed with a particulate of a larger specific size designed to prevent the passage of formation sand or other fines.
An example of such a mechanical swell screen is PETROGUARD™ Swell screens, which are commercially available from Halliburton Energy Services. PETROGUARD™ swell screens provide an alternative to traditional expandable sand-control techniques. The design combines Halliburton's SWELL TECHNOLOGY™ systems with bonded mesh filtration media provide a self-expanding screen that delivers the benefits associated with traditional expandable solutions, but with greatly reduced risk. The PETROGUARD™ swell screens utilize a base pipe with a sheath of an oil-swellable elastomer.
When the elastomer is formed into the form of a sheath around a piece of pipe or other tubular, the result of the swelling is an increase of the outside diameter of the oil-swellable elastomer on the tubular. The oil-swellable elastomer is developed by contact with oil in order to swell and seal between casing strings or pipe and open hole. Swelling of the packer is consistent along its length. Oil continues to diffuse into the elastomer causing the packing element to swell until it reaches the inside diameter of the open borehole. At this point a differentially sealing annular barrier can be created.
Operationally, the benefit of a swellable packer is simplicity. There are no moving parts required to work, through pipe manipulation or by applied hydraulic pressure. No special service personnel are needed. The packers are simply run to depth, similar to a casing, and allowed to swell before production or injection operations begin.